In recent years, industrial and utility concerns with deregulation and operational costs have strengthened demands for increased power plant efficiency. The Rankine cycle power plant, which typically utilizes water as the working fluid, has been the mainstay for the utility and industrial power industry for the last 150 years. In a Rankine cycle power plant, heat energy is converted into electrical energy by heating a working fluid flowing through tubular walls, commonly referred to as waterwalls, to form a vapor, e.g., turning water into steam. Typically, the vapor will be superheated to form a high pressure vapor, e.g., superheated steam. The high pressure vapor is used to power a turbine/generator to generate electricity.
Conventional Rankine cycle power generation systems can be of various types, including direct-fired, fluidized bed and waste-heat type systems. In direct fired and fluidized bed type systems', combustion process heat is generated by burning fuel to heat the combustion air which in turn heats the working fluid circulating through the system's waterwalls. In direct-fired Rankine cycle power generation systems the fuel, commonly pulverized-coal, gas or oil, is ignited in burners located in the waterwalls. In bubbling fluidized bed Rankine cycle, power generation system pulverized-coal is ignited in a bed located at the base of the boiler to generate combustion process heat. Waste-heat Rankine cycle power generation systems rely on heat generated in another process, e.g., incineration for process heat to vaporize, and if desired superheat, the working fluid. Due to metallurgical limitations, the highest temperature of the superheated steam does not normally exceed 1050.degree. F. (566.degree. C.). However, in some "aggressive" designs, this temperature can be as high as 1100.degree. F. (593.degree. C.).
Over the years, efficiency gains in Rankine cycle power systems have been achieved through technological improvements which have allowed working fluid temperatures and pressures to increase and exhaust gas temperatures and pressures to decrease. An important factor in the efficiency of the heat transfer is the average temperature of the working fluid during the transfer of heat from the heat source. If the temperature of the working fluid is significantly lower than the temperature of the available heat source, the efficiency of the cycle will be significantly reduced. This effect, to some extent, explains the difficulty in achieving further gains in efficiency in conventional, Rankine cycle-based, power plants.
In view of the above, a departure from the Rankine cycle has recently been proposed. The proposed new cycle, commonly referred to as the Kalina cycle, attempts to exploit the additional degree of freedom available when using a binary fluid, more particularly an ammonia/water mixture, as the working fluid. The Kalina cycle is described in the paper entitled: "Kalina Cycle System Advancements for Direct Fired Power Generation", co-authored by Michael J. Davidson and Lawrence J. Peletz, Jr., and published by Combustion Engineering, Inc. of Windsor, Conn.
Efficiency gains are obtained in the Kalina cycle plant by reducing the energy losses during the conversion of heat energy into electrical output.
A simplified conventional direct-fired Kalina cycle power generation system is illustrated in FIG. 1 of the drawings. Kalina cycle power plants are characterized by three basic system elements, the Distillation and Condensation Subsystem (DCSS) 100, the Vapor Subsystem (VSS) 110 which includes the boiler 142, superheater 144 and recuperative heat exchanger (RHE) 140, and the turbine/generator subsystem (TGSS) 130. The DCSS 100 and RHE 140 are sometimes jointly referred to as the Regenerative Subsystem (RSS) 150. The boiler 142 is formed of tubular walls 142a and the superheater 144 is of tubular walls and/or banks of fluid tubes 144a. A heat source 120 provides process heat 121. A portion 123 of the process heat 121 is used to vaporize the working fluid in the boiler 142. Another portion 122 of the process heat 121 is used to superheat the vaporized working fluid in the superheater 144.
During normal operation of the Kalina cycle power system of FIG. 1, the ammonia/water working fluid is fed to the boiler 142 from the RHE 140 by liquid stream FS 5 and from the DCSS 100 by liquid stream FS 7. The working fluid is vaporized, i.e., boiled, in the tubular walls 142a of the boiler 142. The rich working fluid stream FS 20 from the DCSS 100 is also vaporized in the heat exchanger(s) of the RHE 140.
In one implementation, the vaporized working fluid from the boiler 142 along with the vaporized working fluid FS 9 from the RHE 140, is further heated in the tubular walls/fluid tube bank 144a of the superheater 144. The superheated vapor as vapor FS 40 from the superheater 144 is directed to, and powers, the TGSS 130 so that electrical power 131 is generated to meet the load requirement. In an alternative implementation, the RHE 140 not only vaporizes but also superheats the rich stream FS 20. In such a case, the superheated vapor flow FS 9' from the RHE 140 is combined with the superheated vapor from the superheater 144 to form vapor flow FS 40 to the TGSS 130.
The expanded working fluid extraction FS 11 egresses from the TGSS 130, e.g., from an intermediate pressure (IP) or a low it pressure (LP) turbine (not shown) within the TGSS 130, and is directed to the DCSS 100. This expanded working fluid is, in part, condensed in the DCSS 100. Working fluid condensed in the DCSS 100, as described above, forms feed fluid FS 7 to the boiler 142. Another key feature of the DCSS 100 is the separation of the working fluid egressing from TGSS 130 into ammonia rich and ammonia lean streams for use by the VSS 110. In this regard, the DCSS 100 separates the expanded working fluid into an ammonia rich working fluid flow FS 20 and an ammonia lean working fluid flow FS 30. Waste heat 101 from the DCSS 100 is dumped to a heat sink, such as a river or pond.
The rich and lean flows FS 20, FS 30, respectively are fed to the RHE 140. Another somewhat less expanded hot working fluid extraction FS 10 egresses from the TGSS 130, e.g., from a high pressure (HP) turbine (not shown) within the TGSS 130, and is directed to the RHE 140. Heat is transferred from the expanded working fluid-extraction FS 10 and the working fluid lean stream FS 30 to the rich working fluid flow FS 20, to thereby vaporize the rich flow FS 20 and condense, at least in part, the expanded working fluid extraction FS 10 and lean working fluid flow FS 30, in the RHE 140. As discussed above, the vaporized rich flow is fed to either the superheater 144, along with vaporized fluid from the boiler 142, or is combined with the superheated working fluid from the superheater 144 and fed directly to the TGSS 130. The condensed expanded working fluid from the RHE 140 forms part of the feed flow, i.e., flow FS 5, to the boiler 142, as has been previously described.
FIG. 2 details a portion of the RHE 140 of VSS 110 of FIG. 1. As shown, the RHE 140 receives ammonia-rich, cold high pressure stream FS 20 from DCSS 100. Stream FS 20 is heated by ammonia-lean hot low pressure stream FS 3010. The stream FS 3010 is formed by combining the somewhat lean hot low pressure extraction stream FS 10 from TGSS 130 with the lean hot low pressure stream FS 30 from DCSS 100, these flows being combined such that stream FS 30 dilutes stream FS 10 resulting in a desired concentration of ammonia in stream FS 3010.
Heat energy 125, is transferred from stream FS 3010 to rich stream FS 20. As discussed above, this causes the transformation of stream FS 20 into a high pressure vapor stream FS 9 or the high pressure superheated vapor stream FS 9', depending on the pressure and concentration of the rich working fluid stream FS 20. This also causes the working fluid stream FS 3010 to be condensed and thereby serve as a liquid feed flow FS 5 to the boiler 142.
As previously indicated, in one implementation the vapor stream FS 9 along with the vapor output from boiler 142 form the vapor input to the superheater 144, and the superheater 144 superheats the vapor input to form superheated vapor stream FS 40 which is used to power TGSS 130. Alternatively, the superheated vapor stream FS 91 along with the superheated vapor output from the superheater 144 form the superheated vapor stream FS 40 to the TGSS 130.
FIG. 3 illustrates exemplary heat transfer curves for heat exchanges occurring in the RHE 140 of FIG. 2. A typical Kalina cycle heat exchange is represented by curves 520 and 530. As shown, the temperature of the liquid binary working fluid FS 20 represented by curve 520 increases as a function of the distance of travel of the working fluid through the heat exchanger of the RHE 140 in a substantially linear manner. That is, the temperature of the working fluid continues to increase even during boiling as the working fluid travels through the heat exchanger of the RHE 140 shown in FIG. 2. At the same time, the temperature of the liquid working fluid FS 3010 represented by curve 530 decreases as a function of the distance of travel of this working fluid through the heat exchanger of the RHE 140 in a substantially linear manner. That is, as heat energy 125 is transferred from working fluid FS 3010 to the working fluid stream FS 20 as both fluid streams flow in opposed directions through the RHE 140 heat exchanger of FIG. 2, the binary working fluid FS 3010 loses heat and the binary working fluid stream FS 20 gains heat at substantially the same rate within the Kalina cycle heat exchangers of the RHE 140.
In contrast, a typical Rankine cycle heat exchange is represented by curve 510. As shown, the temperature of the water or water/steam mixture forming the working fluid represented by curve 510 increases as a function of the distance of travel of the working fluid through a heat exchanger of the type shown in FIG. 2 only after the working fluid has been fully evaporated, i.e., vaporized. The portion 511 of curve 510 represents the temperature of the water or water/steam mixture during boiling. As indicated, the temperature of the working fluid remains substantially constant until the boiling duty has been completed. That is, in a typical Rankine cycle, the temperature of the working fluid does not increase during boiling; rather, as indicated by portion 512 of curve 510, it is only after full vaporization, i.e., full phase transformation, that the temperature of the working fluid in a typical Rankine cycle increases beyond the boiling point temperature of the working fluid, e.g., 212.degree. F./100.degree. C.
As will be noted, the temperature differential between the stream represented by curve 530, which releases the heat energy, and the Rankine cycle stream represented by curve 510, which absorbs the heat energy, continues to increase during phase transformation. The differential becomes greatest just before complete vaporization of the working fluids. In contrast, the temperature differential between the stream releasing heat energy represented by curve 530, and the Kalina cycle stream represented by curve 520, which absorbs the heat energy, remains relatively small, and substantially constant, during phase transformation. This further highlights the enhanced efficiency of Kalina cycle heat exchange in comparison to Rankine cycle heat exchange.
As indicated above, the transformation in the RHE 140 of the liquid or mixed liquid/vapor stream FS 20 to vapor or superheated vapor stream FS 9 or 9' is possible in the Kalina cycle because, the boiling point of rich cold high pressure stream FS 20 is substantially lower than that of lean hot low pressure stream FS 3010. This allows additional boiling, and in some implementation superheating, duty to be performed in the Kalina cycle RHE 140 and therefore outside the boiler 142 and/or superheater 144. Hence, in the Kalina cycle, a greater portion of the process heat 121 can be used for superheating vaporized working fluid in the superheater 144, and less process heat 121 is required for boiling duty in the boiler 142. The net result is increased efficiency of the power generation system when compared to a conventional Ranking cycle type power generation system.
FIG. 4 further depicts the TGSS 130 of FIG. 1. As illustrated, the TGSS 130 in a Kalina cycle power generation system is driven by a high pressure superheated binary fluid vapor stream FS 40. Relatively lean hot low pressure stream extraction FS 10 is directed from, for instance the exhaust of a high pressure (HP) turbine (not shown) within the TGSS 130 to the RHE 140 as shown in FIGS. 1 and 2. A relatively lean cooler, even lower pressure extraction flow FS 11 is directed from, for instance, the exhaust of an intermediate pressure (IP) or low pressure (LP) turbine (not shown) within the TGSS 130 to the DCSS 100 as shown in FIG. 1. As has been discussed to some extent above and will be discussed further below, both extraction flow FS 10 and extraction flow FS 11 retain enough heat to transfer energy to still cooler higher pressure streams in the DCSS 100 and RHE 140.
FIG. 5A further details the Kalina cycle power generation system of FIG. 1 for a once through, i.e., non-recirculating, system configuration. As shown, working fluid streams FS 5 and FS 7 from the RHE 140 and DCSS 100, respectively are combined to form a feed fluid stream FS 57 which is fed to the bottom of the boiler 142. The working fluid 57 flows through the boiler tubes 142a where it is exposed to process heat 123. The working fluid is heated and vaporized in the boiler tubes 142a, while cooling the boiler walls. Sufficient liquid working fluid must be supplied by feed stream FS 57 to provide an adequate flow to the boiler tubes 142a to ensure proper cooling during system operation. Without an adequate flow to the tubes 142a, the tubes can become overheated causing a premature failure of the tubes, particularly in the combustion chamber, and requiring system shut-down for repair.
The heated working fluid rises in the boiler tubes 142a and the fully vaporized working fluid stream is directed from the boiler tubes 142a as stream FS 8 and combined with the vapor stream FS 9 from the RHE 140. The combined vaporized fluid stream FS 89 is directed to the superheater 144, where it is exposed to process heat 122. The resulting high pressure superheated vapor flow FS 40 is directed from the superheater 144 to the TGSS 130.
The TGSS 130, as shown, includes both an HP turbine 130" and an IP turbine 130". The superheated high pressure vapor stream FS 40 is directed to the TGSS 130', first to the HP turbine 130' and then to the IP turbine 130". The vapor flow FS 40 must be sufficient to provide the necessary energy to drive the turbines so that the required power is generated.
The lower pressure hot working fluid exhausted from the HP turbine 130' is split into a lower pressure vapor working fluid stream FS 40' to the IP turbine 130" and an extraction flow FS 40" to the RHE 140. Typically, approximately 50% of the exhaust flow from the HP turbine 130' is spilt off as stream FS 40" to RHE 140, although this may vary. The even lower pressure hot working fluid exhausted from the IP turbine 130" is split into a working fluid stream FS 11 to the DCSS 100 and extraction flow FS 40'" to the RHE 140. It will be understood that the TGSS 130 could also include other turbines, e.g., an LP turbine, to which a portion of the fluid flow from the IP turbine might be first directed before being released from the TGSS 130 to the DCSS 100. The lean hot working fluid extraction streams FS 40" and FS 40'" from the TGSS 130 are combined to form stream FS 10, which is further combined, as previously discussed, with lean hot working fluid stream FS 30 from the DCSS 100 to form a hot working fluid stream FS 3010. Stream FS 3010 is directed on to the RHE 140.
The RHE 140, as previously described receives the hot stream FS 3010 and from the DCSS 100 a rich cold fluid stream FS 20. Heat is transferred from the stream FS 3010 to vaporize stream FS 20. During this process, the stream FS 3010 is condensed to form condensate 3010' which is fed to the boiler 142 as liquid stream FS 5.
FIG. 5B further details the Kalina cycle power generation system of FIG. 1 for a recirculating drum system configuration. The TGSS 130 and RHE 140 of FIG. 5B are substantially identical to those described above with reference to FIG. 5A and therefore will not be further described herein to avoid unnecessary duplication.
As shown, working fluid FS 5 and FS 7 are fed from the RHE 140 and DCSS 100, respectively, and combined to form a feed working fluid stream FS 57 to the drum 142b of the boiler 142. The drum 142b serves not only as a receptacle for the fed fluid but also as a gravity separator which separates out any non-vaporized component of the working fluid received from the tubular walls 142a of the boiler 142. The liquid or mixed liquid/vapor working fluid 57' in the drum 142b is forced by gravity through the boiler tubes 142a where it is exposed to process heat 123. The working fluid is heated and vaporized, while cooling the boiler walls. Sufficient liquid working fluid 57' must be present in the drum 142b to supply an adequate flow to the boiler tubes 142a to ensure proper cooling during system operation. Here again, without an adequate flow to the tubes 142a, the tubes can become overheated causing a premature failure of the tubes, particularly in the combustion chamber, and requiring system shut-down for repair.
The heated working fluid rises in the boiler tubes 142a and the fully vaporized working fluid 57" is separated from any liquid or mixed liquid/vapor working fluid in the drum 142b. The separated vaporized working fluid is directed from the drum 142b as stream FS 8 and combined with the vapor stream FS 9 from the RHE 140. As discussed above, the combined vaporized fluid stream FS 89 is directed to the superheater 144, where it is exposed to process heat 122. The resulting high pressure superheated vapor flow FS 40 is directed from the superheater 144 to the TGSS 130.
Conventional Kalina cycle power generation systems are designed as constant pressure self-balancing systems. That is, conventional Kalina cycle systems are designed to provide the superheated vapor flow needed by the TGSS 130 to generate the required power to meet the load demand, while at the same time providing the necessary feed fluid flow to the boiler to cool the boiler tubes, without actively controlling the fluid flows within the system. Although Kalina cycle power generation test systems are in operation, no Kalina cycle power generation system is believed to have, as yet, been placed in commercial operation. While Kalina cycle power generation test systems which are in operation may be sufficiently self-balancing over the design load range when operated under the test conditions, certain operational and/or environmental factors which arise in commercially operating power generation systems could potentially cause a dangerous system imbalance in conventional Kalina cycle power generation systems.
More particularly, commercially operating power generation systems occasionally encounter conditions which are unpredictable, and hence outside of the system design specifications. For example, fuel, such as pulverized coal, meeting the design specification fuel grade requirements may be unavailable and therefore a different, perhaps lower grade fuel may need to be used to generate the process heat for at least limited periods of operation. In such cases it may not be possible to generate the requisite amount of process heat with the lower grade fuel. Extremes in the environment conditions, such as in the ambient temperature, humidity and atmospheric pressure may be experienced during certain operating periods, with the result that the temperature and pressure relationship which the system requires are unable to be met. Additionally, unusually large and/or quick swings in load demand and hence the power generation requirements may occur, making it difficult, if not impossible, for a conventional Kalina power generation system to accomplish the necessary self-balancing in the required time frame to avoid insufficient working fluid flows within the system, e.g., insufficient superheated vapor FS 40 being, provided to the TGSS 130 and/or insufficient feed fluid 57 being provided to the boiler tubes 142a. Accordingly, problems may arise in the operation of conventional self balancing Kalina cycle power generation systems when subjected to conditions which occasionally occur in the operation of commercially implemented power generation systems.
FIG. 6 illustrates exemplary conventional flow splits and heat transfers within the RHE 140 of FIGS. 5A and 5B. As shown, the RHE 140 includes multiple heat exchangers 140a, 140b, 140c, 140d and 140e with three separate condensate chambers (as shown in heat (exchangers 140a-140c). The extraction FS 10 from the TGSS 130 is combined with the lean hot stream FS 30 from the DCSS 100 to form stream FS 3010 as has been previously described. It should be noted that the stream FS 30 is preheated in heat exchanger 140b of the RHE 140 to form stream FS 30' before being combined with the flow from the TGSS 130 to form stream FS 3010.
The flow FS 3010 is split into a primary stream FS 3010a, and secondary streams FS 3010b and FS 3010c, each being directed to a respective heat exchanger 140a-140c.
The stream FS 3010a releases heat in the primary heat exchanger 140a to vaporize and/or superheat the flow FS 20' and is thereby transformed into the primary condensate 3010a' which will be fed as stream FS 3010a' from the heat exchanger 140a. The stream FS 3010b releases heat in the secondary heat exchanger 140b to heat the flow FS 30 and is thereby transformed into the secondary condensate 3010b' which will be fed as stream FS 3010b' from the heat exchanger 140b. The stream FS 3010c transfers heat in the secondary heat exchanger 140c to heat the flow FS 3010a" and is thereby transformed into the secondary condensate 3010c' which will be fed as stream FS 3010c' from the heat exchanger 140c.
Stream FS 20' is formed by preheating the rich cold stream FS 20 from the DCSS 100 in heat exchanger 140d with heat released from the warm lean condensate FS 3010' flowing from the heat exchangers 140a-140c. FS 3010' is thereby transformed into steam FS 3010". The stream FS 3010" is, in part, directed as stream FS 3010a" through secondary heat exchanger 140c thereby being transformed into stream FS 3010a'". Another portion of stream FS 3010" is directed as stream FS 3010b" to heat exchanger 140e, where it receives heat released from a stream FS 810, which may, for example, be another stream from the DCSS 100, and is thereby transformed into stream FS 3010b'". The streams FS 3010a'" and FS 3010b'" are combined to form feed stream FS 5 from the RHE 140 to the boiler 142.
Although the heat balances may be satisfactory under limited operating and environmental conditions with the system operating in a constant pressure mode, under sliding pressure conditions various system anomalies are likely to occur. For example, the heat exchanges in the exchangers 140a-140c may cause too much or too little heat to be transferred to certain flows and could even result in stream FS 5 being vaporized causing system instability, particularly in the drum type system of FIG. 5B. Turning now to the DCSS, as discussed above, the two primary purposes of the DCSS are to produce the rich and lean streams FS 20 and FS 30 to the RHE 140, as for example shown in FIG. 1, and to reject excess heat which cannot be used by the cycle to a low temperature reservoir or other heat sink. Hence, the DCSS can be viewed as a complex distillation subsystem for producing the rich and lean streams and a condenser for ridding the system of excess heat.
FIG. 5C depicts a more detailed representation of the conventional Kalina cycle power generation system of FIG. 1 for a once through, i.e., non-recirculating, system configuration. The boiler 142, superheater 144, and RHE 140 of FIG. 5C are similar to those described above with reference to FIG. 5A and therefore will not be further described to avoid unnecessary duplication. The TOSS 130 of FIG. 5C is generally similar to the TOSS 130 of FIG. 5A, except for the inclusion of a low-pressure (LP) turbine 130'".
As shown in FIG. 5C, the intermediate pressure hot working fluid exhausted from the IP turbine 130" is split into a working fluid stream FS 40"41 to the LP turbine 130'" and an extraction flow FS 40'" to the RHE 140. The low pressure hot working fluid exhausted from the LP turbine 130'" is exhausted as a hot, relatively dry, vapor working fluid stream FS 11 which is directed to the DCSS 100. The stream FS 11 is relatively rich in ammonia.
FIG. 5C also further details the DCSS 100. It should be noted that the DCSS 100 as shown is still a somewhat simplified depiction, but will be sufficient to those skilled in the art for purposes of this disclosure. As shown the vapor exhaust stream FS 11 is directed through an initial heat exchanger 1510a which extracts heat from working fluid steam FS 11, transforming the stream into a somewhat cooler rich vapor stream FS 11' which is directed to a low pressure (LP) condenser 1500a. The vapor stream FS 11' transfers heat to a cooling liquid stream FS 101', which is typically a cool water stream from a reservoir, such as a cooling tower river or lake. The vapor working fluid from stream FS 11' is fully condensed in the LP condenser 1500a, forming a rich working fluid 20a which is directed as a fluid stream FS 20a to the heat exchanger 1510a.
The liquid working fluid in stream FS 20a is partially vaporized in the heat exchanger 1510a and this partially vaporized working fluid is transported as stream FS 20a' to the separator 1520a. The two phase, i.e. liquid/vapor, working fluid is separated in the separator 1520a into a lean liquid 30a and a rich vapor 30aa. The lean liquid is directed as flow FS 30a' so as to be combined with the somewhat cooled vapor working fluid FS 11' exhausted from the heat exchanger 1510a. By combining the lean liquid flow FS 30a' with the still hot rich vapor flow FS 11', the temperature and more importantly the concentration of the working fluid flow FS 3011a to the LP condenser 1500a is made leaner. More particularly, the concentration of ammonia in the vapor working fluid entering the LP condenser 1500a is significantly reduced. Accordingly, the vapor in stream FS 3011a can be condensed at a lower pressure than the pressure at which the working fluid in stream FS 11', could be condensed. This in turn reduces the pressure at the outlet of the LP turbine allowing greater work to be performed in the LP turbine.
As shown, the rich vapor 30aa is directed from the separator 1520a to another of a cascading series of condensers, heat exchangers and separators. It will be recognized that the series of condensers/heat exchangers/separators, although shown as a series of three could in fact be more or perhaps even less in number. In any event, the rich vapor from the separator 1520a is directed as a stream FS 30aa' to a heat exchanger 1510b where it releases heat to a stream FS 20b formed of condensate collected in the intermediate pressure (IP) condenser 1500b. The somewhat cooled vapor working fluid stream FS 30aa" is output from the heat exchanger 1510b and combined with a leaner liquid working fluid stream FS 30b' from the separator 1520b to form a somewhat leaner vapor stream FS 30ab which is directed to the IP condenser 1500b. Stream FS 30ab is condensed by releasing heat to a stream FS 101' from the reservoir to form the condensate 20b.
The condensate 20b is directed as a liquid stream FS 20b to the heat exchanger 1510b. The heat released from the vapor stream FS 30aa' partially vaporizes the working fluid in stream FS 20b in the exchanger 1510b. This two phase working fluid is then passed as stream FS 20b' to the separator 1520b which separates the stream into a rich vapor 30bb and lean liquid 30b. As discussed above the lean liquid 30b is transported as a liquid stream FS 30b' so as to be mixed with the rich vapor stream FS 30aa' leaving the heat exchanger prior to entering the I0P condenser 1500b. The rich vapor 30bb is transported as a vapor stream 30bb' to the heat exchanger 1510c.
In the exemplary configuration shown, the rich vapor stream FS 30bb' enters the heat exchanger 1510c. The vapor stream FS 30bb', releases heat to the lean condensate stream FS 20c from the high pressure (HP) condenser 1500c in the heat exchanger 1510c. The somewhat cooled vapor stream FS 30bb' is combined, downstream of the heat exchanger 1510c but upstream of the HP condenser 1500c with a lean liquid stream FS 30c' from the separator 1520c to form a somewhat leaner vapor working fluid stream FS 30bc".
The combined stream FS 30bc" is directed to the condenser and condensed by cooling reservoir stream FS 101' to form the condensate 20c. The condensate 20c is a rich liquid working fluid which forms the rich liquid stream FS 20 to the RHE 140. The condensate 20c also is directed as a stream FS 20c to the heat exchanger, where it is partially vaporized by the heat released from stream FS 30bb' before forming the two phase working fluid stream FS 20c' to the separator 1520c. The separator separates the two-phase working fluid into a rich vapor 30cc and lean liquid 30c. A stream FS 30cc" of lean liquid 30c and a rich vapor stream FS 30cc' from the separator 1520c are provided to a further heat exchanger/separator 1530 to form the lean hot vapor stream FS 30 which is provided by the DCSS 100 to the RHE 140. The operation of the heat exchanger/separator 1230 is well understood by those skilled in the art and is therefore not further detailed herein.
As mentioned above, conventional Kalina cycle power generation systems are designed as constant pressure self-balancing systems, and hence lack active control of the fluid flows within the system. However, as also previously noted, while this may be satisfactory under test conditions, in a commercial operating environment power generation systems occasionally encounter conditions which are outside of the system design specifications. Such conditions are likely to make it difficult if not impossible for conventional Kalina power generation systems to accomplish the necessary self balancing in the required time frame to avoid operational problems. For example under certain conditions, the conventional self balancing Kalina cycle power generation system could produce insufficient condensate at HP condenser 1500c to satisfy the demands for rich working fluid stream FS 20 without completely draining the condenser.